Coal bed methane is methane that is found in coal seams. Methane is a significant by-product of coalification, the process by which organic matter becomes coal. Such methane may remain in the coal seam or it may move out of the coal seam. If it remains in the coal seam, the methane is typically immobilized on the coal face or in the coal pores and cleat system. Often the coal seams are at or near underground water or aquifers, and coal bed methane production is reliant on manipulation of underground water tables and levels. The underground water often saturates the coal seam where methane is found, and the underground water is often saturated with methane. The methane may be found in aquifers in and around coal seams, whether as a free gas or in the water, adsorbed to the coal or embedded in the coal itself.
Methane is a primary constituent of natural gas. Recovery of coal bed methane can be an economic method for production of natural gas. Such recovery is now pursued in geologic basins around the world. However, every coal seam that produces coal bed methane has a unique set of reservoir characteristics that determine its economic and technical viability. And those characteristics typically exhibit considerable stratigraphic and lateral variability.
In coal seams, methane is predominantly stored as an immobile, molecularly adsorbed phase within micropores of the bulk coal material. The amount of methane stored in the coal is typically termed the gas content.
Methods of coal bed methane recovery vary from basin to basin and operator to operator. However, a typical recovery strategy is a well is drilled to the coal seam, usually a few hundred to several thousand feet below the surface; casing is set to the seam and cemented in place in order to isolate the water of the coal from that of surrounding strata; the coal is drilled and cleaned; a water pump and gas separation device is installed; and water is removed from the coal seam at a rate appropriate to reduce formation pressure, induce desorption of methane from the coal, and enable production of methane from the well.
Assessment of the economic and technical viability of drilling a coal bed methane well in a particular location in a particular coal seam requires evaluation of a number of reservoir characteristics. Those characteristics include the gas content and storage capability of the coal; the percent gas saturation of the coal; density, permeability, and recovery factor. the gas desorption rate and coal permeability anisotropy; and gas recovery factor.
While industry has developed methods to enhance production from formations that exhibit poor physical characteristics such as permeability and density, practical methods to increase the gas content of a coal seam remain under development. Thus, identifying coal seams that contain economic amounts of methane is a critical task for the industry. The primary issue developing a method in identifying such coal seams involves developing a method and apparatus to quickly and accurately analyze coal seams for gas content.
Currently accepted methods of measuring gas content involve extracting a sample of the coal from the seam and measuring the amount of gas that subsequently desorbs, either by volume or with a methane gas sensor. However, collection of the coal sample usually changes its gas content to a significant extent before gas desorption is monitored. This degradation of sample integrity leads to degradation of the data collected. That degradation of data creates significant doubt in the results of those common methods. As well, because these methods hinge on waiting for the methane to desorb from the coal, they require inordinate amounts of time and expense before the data is available.
Downhole sensing of chemicals using optical spectroscopy is known for oil wells. For example, Smits et. al., “In-Situ Optical Fluid Analysis as an Aid to Wireline Formation Sampling”, 1993 SPE 26496, developed an ultraviolet/visible spectrometer that could be placed in a drill string. That spectrometer was incorporated in a formation fluid sampling tool whereby formation fluids could be flowed through the device and analyzed by the spectrometer. That spectrometer was largely insensitive to molecular structure of the samples, although it was capable of measuring color of the liquids and a few vibrational bond resonances. The device only differentiates between the 0-H bond in water and the C—H bond in hydrocarbons and correlates the color of the analyte to predict the composition of the analyte. The composition obtained by the device is the phase constituents of the water, gas and hydrocarbons. By correlating observation of gas or not gas with observation of water, hydrocarbon, and/or crude oil, the instrument can distinguish between separate phases, mixed phases, vertical size of phases, etc. By correlating the gas, hydrocarbon, and crude oil indicators, the instrument can presumably indicate if a hydrocarbon phase is gaseous, liquid, crude, or light hydrocarbons. A coal bed methane well with coal to methane and, possibly, bacterial material, provides an environment too complex for such a device to differentiate methane and the other substances of interest. The device is not capable of resolving signals from different hydrocarbons to a useful extent, and the device is not capable of accurate measurements needed for coal bed methane wells. Furthermore, the requirements that the sample be fluid, that analysis occur via optical transmission through the sample, and that the sample be examined internal to the device precludes its use for applications such as accurately measuring gas content of coal seams.
In other apparatuses known in U.S. Pat. No. 4,802,761 (Bowen et. al.) and U.S. Pat. No. 4,892,383 (Klainer, et. al.), a fiber optic probe is positioned to transmit radiation to a chemically filtered cell volume. Fluid samples from the surrounding environment are drawn into the cell through a membrane or other filter. The fiber-optic probe then provides an optical pathway via which optical analysis of the sample volume can be affected. In the method from Bowen et. al., a Raman spectrometer at the well head is used to chemically analyze the sample via the fiber optic probe. The method allows purification of the downhole fluid samples via of the wellhead is the fiber optic downhole fluid samples using chromatographic filters and subsequent analysis of the fluid and its solutes using Raman spectroscopy. However, the stated requirement that the Raman spectrometer be remote from the samples of interest and that it employ fiber-optic transmission devices for excitation and collection ensures that the sensitivity of the device is limited. The device further does not consider the conditions present in subsurface wells when analyzing the samples. Furthermore, as in the Smits et. al. case, the requirements in Bowen et. al. and Klainer et. al. that the sample be fluid and that the sample be examined internal to the device significantly decrease the utility of the device for applications such as measuring gas content of coal seams.
Methods of sample preparation and handling for well tools have been described, as well. In U.S. Pat. No. 5,293,931 (Nichols et. al.), an apparatus is disclosed for isolating multiple zones of coal bed formations (coal seams) in a well bore. The isolation allows isolated pressure measurements through the well bore or wellhead collection of samples of fluids from various positions in the wellbore. However, such wellhead sample collection degrades sample integrity and does not provide a practical method or apparatus for assessment of gas content in coal seams. The apparatus shown significantly affects any sample collected and is basically a collection device set down a well.
An object of the invention is to provide a method and system—to accurately measure substances in wells using optical analysis.
Another object of the invention is to provide a method and measuring system capable of measuring methane in a coal bed methane well.
Another object of the invention is to provide a method and measuring system which utilizes a spectrometer to analyze methane and other substances with emitted, reflected or scattered radiation from the substances and thereby allow a measurement of a side surface of the well.
Another object of the invention is to provide a method and measuring system to accurately measure a concentration of methane in a coal bed methane well and calculate a concentration versus depth for a single well and calculate concentrations versus depth for other wells to thereby predict a potential production of a coal bed methane field.
The objects are achieved by a measuring system for introduction into a well with a housing traversable up and down the well, a guide extending down the well from a fixed location and being operatively connected to the housing, a spectrometer being located inside the housing and including a radiation source, a sample interface to transmit a radiation from the radiation source to a sample, and a detector to detect a characteristic radiation emitted, reflected or scattered from the sample and to output a signal, and a signal processor to process the signal from the detector and calculate a concentration of a substance in the sample.
Another aspect of the invention is a measuring system. A portion of the system is introduced into a well with a housing traversable up and down the well, a guide extending down the well from a fixed location and being operatively connected to the housing. The housing incorporates a radiation source, which is electrically powered, either by a battery located in the probe or via the guide wire, a sample interface to transmit a radiation from the radiation source to a sample, and an optical pathway for transmission of a characteristic radiation emitted, reflected or scattered from a sample to a detector situated in a spectrometer located at ground surface. The detector is optically connected to the housing. The surface spectrometer also includes a signal processor to process the signal output from the detector with the measurement system including means to calculate a concentration of a substance in the sample.
Another aspect of the invention is a measuring system for in-situ measurements down a well by a surface spectrometer. The spectrometer includes a radiation source and a detector. A probe is provided optically connected to the spectrometer and including an optical pathway for transmission of a radiation from the radiation source and at least a second optical pathway for transmission of a characteristic radiation from a sample to the detector. A positioner is provided to position the probe near a side surface of the borehole and to optically couple the optical pathways to the side surface of the borehole, wherein the probe is traversable up and down the well by way of a guide operatively connected to the probe and to a fixed location at the wellhead.
Another aspect of the invention is a measuring system for in-situ measurements down a well by a surface spectrometer, which includes a detector. A probe is provided that is optically connected to the spectrometer. The probe houses a radiation source, which is electrical powered, either by a battery located in the probe or via a guide wire, and an optical pathway for transmission of a characteristic radiation from a sample to the detector. A positioner is provided to position the probe near a side surface of the borehole and to optically couple the optical pathways to the side surface of the borehole, wherein the probe is traversable up and down the well by way of a guide operatively connected to the probe and to a fixed location at the wellhead
Another aspect of the invention is a method of measuring methane in at least one coal bed methane well. An instrument package is provided in a housing, and the housing is lowered a distance down the well. A radiation source is positioned to irradiate a sample, and a detector is positioned to detect the characteristic radiation from the interaction between the sample and the incident radiation from the radiation source. The sample is irradiated to produce the characteristic radiation. The concentration of methane in the sample is measured by detecting the characteristic radiation with the detector. The detector transmits a signal representative of the concentration of methane to a signal processor, and the signal processor processes the signal to calculate the concentration of methane in the sample.
In another aspect of the invention, a method of measuring a side surface of a borehole using optical spectrometers is provided. An optical spectrometer with a radiation source and a detector is provided. The side surface of the borehole is optically connected to the radiation source and the detector. The radiation source irradiates the side surface of the borehole, and the emitted, reflected or scattered characteristic radiation from the side surface of the borehole is collected. The collected characteristic radiation is transmitted to the detector to output or produce a signal. The signal is transmitted to a signal processor and the concentration of a substance on the side surface of the borehole is calculated.
The side surface is usually a solid material such as coal, sandstone, clay or other deposit. The side surface has been affected by the drill bit. The side surface may also have a film of drilling “mud” or some other contaminant (introduced or naturally found) that has been distributed by the drill bit. The measurement system analyzes the surface of that material, or the material is penetrated to analyze its interior. The surface may be treated (i.e. by washing it with water) before being analyzed. The material of interest is characterized along with any other materials adsorbed or absorbed to the material. These could include gases, liquids, or solids. Preferably, the methane adsorbed to the coal surface and in its pores is identified. The amount of methane on the surface and in the pores is measured.
The samples of interest may be a face of the coal seam, the coal itself, a bacterium or bacterial community which may indicate methane, the water in the well, methane entrained in the coal or water, methane dissolved in the water; or free gas. A free gas may be examined in-situ by providing a pressure change to the water or to the coal and collecting the resultant gas by way of a head-space. The sample or substance of interest may be physically, biologically or chemically treated in-situ before measuring to enhance detection or measurement.
The radiation source is of particular concern and is selected depending on the well environment, the substance to be measured and the background of the sample. Coal shows inordinate fluorescence, and often bacteria and other organic material are present near the coal seams. These substances tend to produce fluorescence which interferes with measurements of other substances. Unless the fluorescence is measured, the radiation source and wavelength are selected to minimize these effects. Coal tends to fluoresce between 600 nm and 900 nm with a significant drop in fluorescence under 600 nm. A radiation source which takes into account these ranges is preferred for measuring the methane, especially the methane adsorbed to or embedded in the coal. Thus, the methane signature relative to the other components is maximized. In some instances a signature of the fluorescence is maximized to characterize the methane indirectly.
The measurements lead to establishing a concentration of methane in the coal bed formation and to the potential production or capacity of the coal bed. The methane is analyzed by obtaining through spectrometers a series of spectra representative of scattered, emitted or reflected radiation from methane in the well. The captured spectra are used to determine the concentration at varying depths of methane present in the coal bed formation. The spectra are manipulated and analyzed to produce the concentrations of methane represented in the well. The use of filters which are designed to eliminate or reduce radiation from sources present in the well is needed to accurately determine the methane concentration or other parameters of the coal bed methane well. Other parameters may include a predictor element or compound that is natural or introduced to the coal bed or well. The filters are chosen depending on the chemical which is of interest. Raman spectrometers are used in most testing, however, near infrared lasers and detectors may be employed to avoid the difficulties associated with fluorescence from material or substances in the water or well. The measuring system in this invention is based on high sensitivity. One factor that is used to maintain high sensitivity of the system is the reduction or elimination of moving parts throughout the measuring system.
Traditionally, coal bed methane production factors have been determined by a variety of methods. One method involves retrieval of a core sample of the coal, transportation of the core sample to a laboratory setting, and quantification of the amount of methane contained within the sample coal via gas desorption. This quantity is then analyzed to determine the coal gas content and compared to an adsorption isotherm of the same or a similar coal in order to determine the critical desorption pressure of the coalbed reservoir. This process is expensive, time consuming, and error-prone.
Those skilled in the art will recognize that reference to a partial pressure of gas dissolved in a fluid is related to the amount of that gas that is dissolved in that fluid and that would be in equilibrium with a vapor phase in contact with that fluid. Use of the term “partial pressure of gas in fluid” is meant to encompass, but not be limited to, related terms such as concentration, effective density, quantity, potential volume, potential pressure, and amount.
An aspect of certain preferred embodiments of the invention provides that a production factor such as gas content, dewatering time, critical desorption pressure, and/or other reservoir and operational variables can be determined via measurement or determination of methane partial pressure or another substance or substances indicative of the methane partial pressure.
The critical desorption pressure of the coal bed methane reservoir or coal seam is equal to the methane partial pressure of the reservoir or coal seam. By determining the effective methane partial pressure of the coal, reservoir fluid or well fluid the critical desorption pressure may be determined. If the system is in physical and chemical equilibrium the partial pressures of methane for the reservoir, coal, reservoir fluid and well fluid are all equal. However, in practice this is not always the case as many variables may affect the partial pressures and their interrelation to one another. In such cases other measurements or determinations may be used to correlate the partial pressures.
Other production factors may be determined utilizing the partial pressure of methane via correlation, modeling, calculation, and other sensor data.
The measurement of the partial pressure of methane can be accomplished via measurement of a dissolved methane concentration. Preferably, the measurement of the concentration is done at a depth of the coal seam and as near to the coal seam as possible so that other variables and effects are lessened. This concentration is then correlated to a partial pressure of methane of the well fluid, reservoir fluid or coal reservoir. The partial pressure of methane within the coal reservoir is then used to determine the critical desorption pressure along with a gas content of the coal reservoir, dewatering time and other reservoir and operational variables.
The measurement or determination of the partial pressure may also be accomplished in other ways such as by direct measurement of the partial pressure via instrumentation or another variable which correlates to the partial pressure of methane.
In a preferred embodiment, the methane concentration or another substance's concentration dissolved in a coal seam reservoir fluid is measured at a depth in the well at or near the coal seam of interest. This concentration is then correlated to a partial pressure of methane in the fluid. This partial pressure of methane in the fluid is then correlated to the partial pressure of methane in the reservoir which equates to the critical desorption pressure.
In certain preferred embodiments of the invention a method for determining a production factor or gas content of a coal seam is achieved by direct measurement of methane concentration of the wellbore fluid. This measurement in combination with a known or determined solubility property for methane in water allows the calculation of the partial pressure of methane in the wellbore fluid.
If the fluid in the wellbore is in equilibrium with the reservoir fluid, which in turn is in equilibrium with the coal seam itself, the hydrologic and physical connection between these fluids and the coal allows that the measurement of one of these partial pressures can be correlated into a measurement of the other two. The partial pressure of the fluids is controlled by the amount of methane present in the coal seam. More simply stated; when more methane is present in a particular coal seam, the partial pressure of methane in the fluids is higher.
The methane partial pressure of the coal seam is the critical desorption pressure, which is the saturation point of the coal seam at that pressure. Dewatering of the well acts to lower the total fluid pressure to a value at or below the critical desorption pressure, which causes devolution of methane out of the coal seam as free gas.
Having determined the critical desorption pressure, by further utilizing an isotherm of the interested coal seam calculations can be made to determine the gas content of the coal seam and estimate the total methane reserves. As well, the critical desorption pressure can be compared to the rate of decrease of the total reservoir pressure during dewatering, the rate of flow of water from the coal seam, and other reservoir and operational variables, in order to predict dewatering time, permeability, and other production factors.
The concentration of the methane or other substance or the partial pressure of methane in the reservoir fluid may be measured by optical spectrometers, membrane-covered semiconductor sensors, mass spectrometers or the like.
The concentration which is measured may be directly correlated to a partial pressure of methane in the reservoir or any intermediate quantity that is relatable to the amount of methane in the fluid or parts of the fluid. Each coal seam has unique properties which may affect the correlations. By using an intermediate correlation these properties may be used to enhance the accuracy and precision of the partial pressure determination of the methane in the reservoir.
The production factors which may be determined are gas partial pressure, percent saturation of gas in coal, gas content, bookable reserves, permeability, porosity, relative permeability, critical desorption pressure, dewatering time, solution gas, stage of production, cone of depression, cross-seam water and gas flow, water salinity, identification of contributing seams and formations, density, coal friability, cleat and fracture structure including size, distribution and orientation, dewatering area and volume, degassing area and volume, gas concentration, reservoir pressure, gas recovery factor, gas-in-place, water and gas production rates and timetables, well lifetime, optimum well spacing, optimum production procedures including choice of which seams in multi-zone wells and which wells in a pod should be produced first, second, etc., optimum completion procedures including choice of which seams and wells to complete first, second, etc., which to abandon or sell, and how to complete and produce the desired wells, effectiveness of prior completion and production activities, indication of regions and seams of favorable production potential, and other production factors which will be apparent to those skilled in the art.
Another aspect of the invention is an apparatus and/or system which measures the partial pressure of methane or another substance indicative of the methane or measures a precursor variable such as the concentration of methane to allow or produce a determination of the methane partial pressure of the reservoir. The system may include a pressure transducer. The pressure transducer can measure the total pressure of the fluid at the measurement point. The transducer can also measure a gas pressure down a wellbore when the methane is evolved from the water.
Preferably, the concentration or partial pressure is measured by Raman spectroscopy. This may be accomplished by lowering a probe or housing within the well which contains the spectrometer or parts thereof or by guiding a radiation from a radiation source into the well and onto the fluid at or near the coal seam from the spectrometer located outside of the well. Characteristic radiation may also be guided from the fluid to the spectrometer located outside the well. Most preferably, the measurement is conducted on the fluid without first sampling the fluid. During sampling, the fluid is necessarily transported and disturbed. By measuring the fluid outside of an instrument package and in-situ the resultant concentration or partial pressure is more accurate.
This invention describes a method of combining physical isolation of subsurface geological formations with spectroscopic analysis of fluids and fluid pressure measurements in order to quickly and accurately measure key properties of multiple formations in a single wellbore. The method enables, in one embodiment, rapid assessment of each formation as a possible natural gas (methane) production target.
Alone, zonal isolation is well known and widely practiced, but is of use only in limited circumstances, such as when measuring fluid movement rates and wellbore pressure changes in order to evaluate permeability and skin damage. Alone, in situ downhole and surface spectroscopic fluid analysis has been perfected and commercially deployed, but it is challenged in some cases by the movement of fluid downhole between formations in the wellbore, complicating analysis and interpretation of results when more than one formation is open to a wellbore.
By combining zonal isolation and downhole spectroscopic fluid analysis in a specific manner, this invention provides the unexpected benefit of enabling in-situ measurement of fluid properties for multiple zones in a single wellbore without requiring an intervening cemented casing, allowing fast, accurate evaluation of multiple possible production zones in a single well. The method further allows differentiation of fluids from each of these zones, and thereby differentiation of the properties of the formations. The method allows the possibility of determination of cross communication between formations at locations away from the wellbore.
A further unexpected benefit involves the resulting ability to move fluids into and out of each formation independently, thereby providing the ability to obtain far acting (i.e. unperturbed from their natural state) reservoir fluids for analysis even in cases where fluid invasion into the formation has occurred.
A further unexpected benefit involves the resulting ability to combine a variety of complementary fluid physical and geochemical measurements, such as carbon isotope enrichment, fluid conductivity, fluid transmissivity, and methane concentration measurements, together with determination of formation bulk permeability, in a single operational test. The method is also suitable for use in a production test mode whereby the fluids are isolated downhole and then delivered to the surface for analysis.
Other objects, advantages and novel features of the present invention will become apparent from the following detailed description of the invention when considered in conjunction with the accompanying drawings.
The accompanying drawings, which are incorporated in and constitute a part of the specification, illustrate preferred embodiments of the invention. These drawings, together with the general description of the invention given above and the detailed description of the preferred embodiments given below, serve to explain the principles of the invention.